EP2870320B1 - Procédé de réduction du broutement en cours de forage de puits - Google Patents

Procédé de réduction du broutement en cours de forage de puits Download PDF

Info

Publication number
EP2870320B1
EP2870320B1 EP13812637.0A EP13812637A EP2870320B1 EP 2870320 B1 EP2870320 B1 EP 2870320B1 EP 13812637 A EP13812637 A EP 13812637A EP 2870320 B1 EP2870320 B1 EP 2870320B1
Authority
EP
European Patent Office
Prior art keywords
drill string
torque
parameter related
drilling
drill
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Active
Application number
EP13812637.0A
Other languages
German (de)
English (en)
Other versions
EP2870320A1 (fr
EP2870320A4 (fr
Inventor
Andrew Derek Normore
Eric E. Maidla
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Services Petroliers Schlumberger SA
Schlumberger Holdings Ltd
Schlumberger Technology BV
Original Assignee
Services Petroliers Schlumberger SA
Schlumberger Holdings Ltd
Schlumberger Technology BV
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Services Petroliers Schlumberger SA, Schlumberger Holdings Ltd, Schlumberger Technology BV filed Critical Services Petroliers Schlumberger SA
Publication of EP2870320A1 publication Critical patent/EP2870320A1/fr
Publication of EP2870320A4 publication Critical patent/EP2870320A4/fr
Application granted granted Critical
Publication of EP2870320B1 publication Critical patent/EP2870320B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Images

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E21B44/02—Automatic control of the tool feed
    • E21B44/04—Automatic control of the tool feed in response to the torque of the drive ; Measuring drilling torque
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00—Special methods or apparatus for drilling
    • E21B7/04—Directional drilling
    • E21B7/06—Deflecting the direction of boreholes
    • E21B7/068—Deflecting the direction of boreholes drilled by a down-hole drilling motor

Definitions

  • This disclosure relates generally to the field of wellbore drilling through subsurface formations. More specifically, the disclosure relates to methods for reducing undesirable modes of motion that induce undesirable vibration levels in a drill pipe "string" used to drill such wellbores.
  • Drilling wellbores through subsurface includes "rotary" drilling, in which a drilling rig or similar lifting device suspends a drill string which turns a drill bit located at one end of the drill string. Equipment on the rig and/or an hydraulically operated motor disposed in the drill string rotate the bit.
  • the drilling rig includes lifting equipment which suspends the drill string so as to place a selected axial force (weight on bit - "WOB") on the drill bit as the bit is rotated.
  • the combined axial force and bit rotation causes the bit to gouge, scrape and/or crush the rocks, thereby drilling a wellbore through the rocks.
  • a drilling rig includes liquid pumps for forcing a fluid called “drilling mud" through the interior of the drill string.
  • the drilling mud is ultimately discharged through nozzles or water courses in the bit.
  • the mud lifts drill cuttings from the wellbore and carries them to the earth's surface for disposition.
  • Other types of drilling rigs may use compressed air as the fluid for lifting cuttings.
  • the forces acting on a typical drill string during drilling are very large.
  • the amount of torque necessary to rotate the drill bit may range to several thousand foot pounds.
  • the axial force may range into several tens of thousands of pounds.
  • the length of the drill string moreover, may be twenty thousand feet or more.
  • the typical drill string is composed of threaded pipe segments having diameter on the order of only a few inches, the combination of length of the drill string and the magnitude of the axial and torsional forces acting on the drill string can cause certain movement modes of the drill string within the wellbore which can be destructive.
  • a well known form of destructive drill string movement is known as "stick-slip", in which the drill string becomes rotationally stopped along its length by friction and is caused to "wind up” by continued rotation from the surface.
  • the friction may be overcome and torsional release of the drill string below the stick point may cause such rapid unwinding of the drill string below the stick point so as to do damage to drill string components.
  • Stick slip may be particularly damaging when certain types of directional drilling devices, called “rotary steerable directional drilling systems" are used. Stick-slip may cause undesirable vibrations that in turn could reduce the life of the drill string components such as bits, motors, MWD equipment, LWD equipment and the BHA.
  • a drilling rig is designated generally at 11.
  • the drilling rig 11 in FIG. 1 is shown as a land-based rig.
  • the examples described herein will find equal application on marine drilling rigs, such as jack-up rigs, semisubmersibles, drill ships, and the like.
  • the rig 11 includes a derrick 13 that is supported on the ground above a rig floor 15.
  • the rig 11 includes lifting gear, which includes a crown block 17 mounted to derrick 13 and a traveling block 19. Crown block 17 and traveling block 19 are interconnected by a cable 21 that is driven by draw works 23 to control the upward and downward movement of the traveling block 19. Traveling block 19 carries a hook 25 from which is suspended a top drive 27.
  • the top drive 27 supports a drill string, designated generally by the numeral 31, in a wellbore 33.
  • a drill string 31 is coupled to the top drive 27 through an instrumented sub 29.
  • the instrumented top sub 29 may include sensors (not shown separately) that provide drill string torque information.
  • a longitudinal end of the drill string 31 includes a drill bit 2 mounted thereon to drill the formations to extend (drill) the wellbore 33.
  • the top drive 27 can be operated to rotate the drill string 31 in either direction, as will be further explained.
  • a load sensor 26 may be coupled to the hook 25 in order to measure the weight load on the hook 25.
  • Such weight load may be related to the weight of the drill string 31, friction between the drill string 31 and the wellbore 33 wall and an amount of the weight of the drill string 31 that is applied to the drill bit 2 to drill the formations to extend the wellbore 33.
  • the drill string 31 may include a plurality of interconnected sections of drill pipe 35 a bottom hole assembly (BHA) 37, which may include stabilizers, drill collars, and a suite of measurement while drilling (MWD) and or logging while drilling (LWD) instruments, shown generally at 51.
  • BHA bottom hole assembly
  • a drilling motor 41 may be connected proximate the bottom of BHA 37.
  • the motor 41 may be any type known in the art for rotating the drill bit 2 and/or selected portions of the drill string 31.
  • Example types of drilling motors include, without limitation, positive displacement fluid operated motors, turbine fluid operated motors, electric motors and hydraulic fluid operated motors.
  • the present example motor 41 may be operated by drilling fluid flow. Drilling fluid is delivered to the drill string 31 by mud pumps 43 through a mud hose 45. In some examples, pressure of the mud may be measured by a pressure sensor 49. During drilling, the drill string 31 is rotated within the wellbore 33 by the top drive 27, in a manner to be explained further below.
  • the top drive 27 is slidingly mounted on parallel vertically extending rails (not shown) to resist rotation as torque is applied to the drill string 31.
  • the manner of rotation of the drill string 31 during drilling will be further explained below.
  • the bit 2 may be rotated by the motor 41, which in the present example may be operated by the flow of drilling fluid supplied by the mud pumps 43.
  • a top drive rig is illustrated, those skilled in the art will recognize that the present example may also be used in connection with systems in which a rotary table and kelly are used to apply torque to the drill string 31.
  • Drill cuttings produced as the bit 2 drills into the subsurface formations to extend the wellbore 33 are carried out of the wellbore 33 by the drilling mud as it passes through nozzles, jets or courses (none shown) in the drill bit 2.
  • Signals from the pressure sensor 49, the hookload sensor 26, the instrumented tob sub 29 and from the MWD/LWD system 51 may be received in automatic drill string rotation controller 48, which will be further explained with reference to FIG. 2 .
  • a trajectory of the wellbore 33 may be selectively controlled (i.e., the wellbore may be drilled along a selected geodetic trajectory) using a "rotary steerable directional drilling system" (RSS).
  • RSS rotary steerable directional drilling system
  • a drill string 31 having a RSS is shown schematically in FIG. 3 at 9.
  • the drill string 31 also includes a motor 41 substantially as explained with reference to FIG. 1 , as well as instrumentation 51 corresponding to any or all of the sensors of the MWD/LWD system explained with reference to FIG. 1 .
  • a kelly 4 is shown for rotating the drill string 31 as explained above.
  • the RSS 9 may include directional sensors, and at least one accelerometer 51A or other sensor responsive to shock and/or vibration.
  • An accelerometer may also be one of the sensors included in the MWD/LWD instrumentation (51 in FIG. 1 ).
  • FIG. 2 shows a block diagram of an example of the automatic drill string rotation controller 48.
  • the automatic drill string rotation controller 48 may include a drill string rotation control system. Such system may include a torque related parameter sensor 53.
  • the torque related parameter sensor 53 may provide a measure of the torque applied to the drill string (31 in FIG. 1 ) at the surface by the top drive or kelly.
  • the torque related parameter sensor 53 may implemented as a strain gage in the instrumented top sub (29 in FIG. 1 ) if it is configured to measure torque.
  • the torque related parameter sensor 53 may also be implemented, for example and without limitation, as a current measurement device for an electric rotary table or top drive motor, as a pressure sensor for an hydraulically operated top drive, or as an angle of rotation sensor for measuring drill string rotation.
  • the torque related parameter sensor 53 may be any sensor that measures a parameter that can be directly or indirectly related to the amount of torque applied to the drill string.
  • the output of the torque related parameter sensor 53 may be received as input to a processor 55.
  • output of the pressure sensor 49 and/or one or more sensors of the MWD/LWD system 51 may also be provided as input to the processor 55.
  • the processor 55 may be any programmable general purpose processor such as a programmable logic controller (PLC) or may be one or more general purpose programmable computers.
  • PLC programmable logic controller
  • the processor 55 may receive user input from user input devices, such as a keyboard 57. Other user input devices such as touch screens, keypads, and the like may also be used.
  • the processor 55 may also provide visual output to a display 59.
  • the processor 55 may also provide output to a drill string rotation controller 61 that operates the top drive (27 in FIG. 1 ) or rotary table ( FIG. 3 ) to rotate the drill string as will be further explained below.
  • the drill string rotation controller 61 may be implemented, for example, as a servo panel (not shown separately) that attaches to a manual control panel for the top drive.
  • a servo panel is provided with a service sold under the service mark SLIDER, which is a service mark of Schlumberger Technology Corporation, Sugar Land, Texas.
  • SLIDER which is a service mark of Schlumberger Technology Corporation, Sugar Land, Texas.
  • the drill string rotation controller 61 may also be implemented as direct control to the top drive motor power input (e.g., as electric current controls or variable orifice hydraulic valves).
  • the type of drill string rotation controller is not a limit on the scope of the present disclosure.
  • the processor 55 operates the drill string rotation controller 61 to cause the top drive (27 in FIG. 1 ) or kelly (4 in FIG. 2 ) to rotate the drill string (31 in FIG. 1 ) in a first direction, while measuring the drill string torque related parameter using the torque related parameter sensor 53.
  • the rotation controller 61 continues to cause the top drive or kelly to rotate the drill string (31 in FIG. 1 ) in the first direction until a first selected value of the torque related parameter is reached.
  • the processor 55 registers the torque related parameter magnitude measured by torque related parameter sensor 53 as having reached the first selected value
  • the processor 55 actuates drill string rotation controller 61 to cause the top drive or kelly to reverse the direction of rotation of the drill string (31 in FIG.
  • the processor 55 continues to accept as input measurements from the torque related parameter sensor 53 and actuates the rotation controller 61 to cause rotation of drill string (31 in FIG. 1 ) back and forth between the first selected parameter value and the second selected parameter value.
  • the back and forth rotation may reduce or eliminate stick/slip friction between the drill string (31 in FIG. 1 ) and the wellbore (33 in FIG. 1 ), thereby making it easier for the drilling rig operator to control, for example, the axial force exerted on the drill bit (2 in FIG. 1 ), called "weight on bit.”
  • FIG. 4 graphically illustrates torque applied to the drill string in order to explain example techniques for selecting the first and second selected torque related parameter values.
  • the graph in FIG. 4 is scaled in torque to help explain the principle of the example method, however, as explained above, any torque related parameter may be used.
  • the drill string (31 in FIG. 1 ) may have zero torque applied by the top drive or kelly.
  • the applied torque increases with respect to amount of rotation, generally until the torque exceeds the frictional force between the drill string and the wellbore wall.
  • the torque stops increasing, because the entire drill string will begin rotating.
  • such torque point 71 may be selected as the first torque related parameter value, or may be set as an upper limit to the first torque related parameter value.
  • the drill string may be rotated in the second direction so as to reduce the torque applied to the drill string. Reduction in torque may continue until the second torque related parameter value is reached.
  • the first direction of drill string rotation may be the same as the direction of "make up" (tightening) the threads (not shown) used to join the segments (35 in FIG. 1 ) of the drill string.
  • rotation of the drill string may be reversed until the first torque related parameter value is reached once again.
  • the foregoing drill string rotation in the first and second directions may be repeated so that the applied torque or torque related parameter varies between the first value, shown by dashed line 72 and the second value, shown by dashed line 74.
  • the second torque related parameter value is lower than the first torque related parameter value, but the torque applied to the drill string remains in the same direction.
  • the drill string may be advanced axially along the wellbore by suitable operation of the rig components that suspend the top drive (or kelly, if used), as explained with reference to FIG. 1 .
  • the second torque related parameter value may be empirically determined.
  • One possible empirical criterion is that torque reduction on the drill string by rotation in the second direction may extend to a selected position along the drill string in the wellbore. Such position may be determined, for example, by calculation using torque and drag calculation programs or algorithms known in the art.
  • the second torque value may be empirically determined so as to reduce stick-slip or other destructive motion of the drill string, where such reduction is shown by a measured parameter, and/or rate of advance of the drill string ("rate of penetration") is optimized.
  • "Optimized" as used in the present context may mean, for example, a maximum value consistent with reduced or eliminated destructive drill string motion and associated shock and vibration.
  • FIG. 5 shows an example, at curve 78, of correspondence between hookload (which corresponds to axial force on the drill bit) or the mud pressure (as measured by the pressure sensor 49 in FIG. 1 ).
  • the hookload may be relatively constant, as shown at 78A. If the second torque related parameter value is too high, as shown at 78C, the drill string may not move axially, indicating sticking, whereupon the hookload may drop as the drill bit is no longer able to drill the formations. If the second torque related parameter value is too low, there may be variations in the hookload, as shown at 78B, indicating undesirable or destructive motion of the drill string. If the motor (41 in FIG.
  • the measured drilling fluid pressure may exhibit the same characteristics with respect to the second torque related parameter value as does the hookload.
  • Other examples of measurements that may be used to select the second torque related parameter value may include, without limitation, acceleration measurements from the accelerometer or similar sensor (51A in FIG. 3 ). Whether the indicated amount of variation in the measured parameter is excessive may be determined, for example, by setting an upper limit of root mean square (RMS) variation or other suitable statistical measure of variability of the measured parameter associated with destructive motion of the drill string.
  • the second selected torque related parameter value may be increased, for example, until the variation falls below a selected threshold.
  • selecting the first and second selected torque related parameter values may be performed, for example, manually by the system operator observing the torque related parameter and the one or more measured parameters on the display (59 in FIG. 2 ), or may be computed automatically by suitable programming implemented on the processor (55 in FIG. 2 ).
  • a method for drilling a wellbore may reduce failure of drill string components and drill string instrumentation, may increase the life of drilling motors, may increase control over wellbore trajectory while drilling with RSS systems, and may increase overall drilling efficiency by optimizing rate of penetration of the formations by the drill bit.
  • the present method may also reduce the amount of drill string rotation and therefore reduce drill string fatigue (e.g. pipe, tool joint failures, and BHA component failures) and reduce wear issues related to pipe rotation (e.g. casing wear, key seating, subsea well head wear for offshore applications).

Landscapes

  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Claims (10)

  1. Procédé destiné au forage d'un puits de forage (33), comprenant :
    le fonctionnement d'au moins un moteur (41) accouplé à l'intérieur d'un train de forage (31) pour faire tourner un trépan (2) à une extrémité de celui-ci ;
    le fonctionnement d'un dispositif de commande de rotation automatique du train de forage (48) pour entraîner la rotation du train de forage (31) à partir de la surface dans une premier sens jusqu'à ce qu'un paramètre de mesure associé au couple (70) sur le train de forage (31) atteigne une première valeur sélectionnée (72) ;
    le fonctionnement du dispositif de commande de la rotation automatique du train de forage (48, 61) pour entraîner la rotation du train de forage (31) à partir de la surface dans un second sens jusqu'à ce que le paramètre mesuré associé au couple (70) soit réduit à une seconde valeur sélectionnée (74), la seconde valeur sélectionnée (74) étant dans un même sens de rotation que la première valeur sélectionnée (72) ;
    le fonctionnement d'un système de forage directionnel orientable rotatif (9) accouplé dans le train de forage (31) pour amener le puits de forage (33) à suivre une trajectoire sélectionnée, dans lequel le système de forage directionnel orientable rotatif (9) est disposé au-dessous dudit au moins un moteur (41) sur le train de forage (31) ; et
    l'avancement du train de forage (31) axialement pour amener le trépan (2) à élargir le puits de forage (33).
  2. Procédé selon la revendication 1, destiné au forage d'un puits de forage (33), comprenant :
    la rotation automatique du train de forage (31) dans le premier sens jusqu'à ce que les paramètres mesurés associés au couple (70) appliqués au train de forage (31) atteignent la première valeur sélectionnée (72) ;
    la rotation automatique du train de forage (31) dans le second sens jusqu'à ce que le paramètre mesuré soit réduit à la seconde valeur sélectionnée (74).
  3. Procédé selon l'une quelconque des revendications précédentes, comprenant en outre la répétition de la rotation du train de forage (31) dans le premier sens, la rotation du train de forage (31) dans le second sens et l'avancement axialement du train de forage (31).
  4. Procédé selon l'une quelconque des revendications précédentes, dans lequel la première valeur sélectionnée (72) est déterminée par le lancement de la rotation du train de forage (31) dans le premier sens jusqu'à ce que le couple mesuré arrête pratiquement d'augmenter.
  5. Procédé selon l'une quelconque des revendications précédentes, dans lequel la seconde valeur sélectionnée (74) est déterminée par la rotation du train de forage (31) dans le second sens et la détermination d'un couple auquel une vitesse de pénétration du train de forage (31) est optimisée.
  6. Procédé selon la revendication 5, dans lequel la vitesse de pénétration optimisée est déterminée en mesurant au moins un paramètre associé au mouvement destructif du train de forage (31) et la détermination du paramètre associé au couple (70) lorsque ledit au moins un paramètre associé au mouvement destructif indique que le mouvement destructif a été pratiquement éliminé.
  7. Procédé selon la revendication 6, dans lequel ledit au moins un paramètre associé au mouvement destructif comprend la charge au crochet (78).
  8. Procédé selon la revendication 6, dans lequel ledit au moins un paramètre associé au mouvement destructif comprend la pression du fluide de forage lorsque le moteur (41) est actionné par l'écoulement de celui-ci.
  9. Procédé selon la revendication 6, dans lequel ledit au moins un paramètre associé au mouvement destructif comprend l'accélération d'un élément du train de forage (31).
  10. Procédé selon la revendication 6, dans lequel une indication de la réduction dans le mouvement destructif comprend la détermination du moment auquel la variation dans le paramètre de mesure associé au m destructif tombe en dessous d'un seuil sélectionné.
EP13812637.0A 2012-07-03 2013-06-28 Procédé de réduction du broutement en cours de forage de puits Active EP2870320B1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US13/541,357 US9145768B2 (en) 2012-07-03 2012-07-03 Method for reducing stick-slip during wellbore drilling
PCT/US2013/048408 WO2014008115A1 (fr) 2012-07-03 2013-06-28 Procédé de réduction du broutement en cours de forage de puits

Publications (3)

Publication Number Publication Date
EP2870320A1 EP2870320A1 (fr) 2015-05-13
EP2870320A4 EP2870320A4 (fr) 2016-03-23
EP2870320B1 true EP2870320B1 (fr) 2019-11-13

Family

ID=49877649

Family Applications (1)

Application Number Title Priority Date Filing Date
EP13812637.0A Active EP2870320B1 (fr) 2012-07-03 2013-06-28 Procédé de réduction du broutement en cours de forage de puits

Country Status (6)

Country Link
US (1) US9145768B2 (fr)
EP (1) EP2870320B1 (fr)
AU (1) AU2013286986B2 (fr)
CA (1) CA2877925C (fr)
MX (1) MX364163B (fr)
WO (1) WO2014008115A1 (fr)

Families Citing this family (16)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6802378B2 (en) * 2002-12-19 2004-10-12 Noble Engineering And Development, Ltd. Method of and apparatus for directional drilling
US9309760B2 (en) 2012-12-18 2016-04-12 Schlumberger Technology Corporation Automated directional drilling system and method using steerable motors
US9650880B2 (en) * 2013-04-12 2017-05-16 Tesco Corporation Waveform anti-stick slip system and method
WO2015161209A1 (fr) 2014-04-17 2015-10-22 Schlumberger Canada Limited Forage coulissant automatique
WO2016060881A1 (fr) * 2014-10-15 2016-04-21 Schlumberger Canada Limited Procédé et appareil de forage directionnel à l'aide d'une tige de forage câblée
WO2017095974A1 (fr) * 2015-12-04 2017-06-08 Schlumberger Technology Corporation Système et procédé de forage directionnel automatisé utilisant des moteurs de forage orientables
US10907412B2 (en) 2016-03-31 2021-02-02 Schlumberger Technology Corporation Equipment string communication and steering
CN106092548B (zh) * 2016-07-28 2019-03-29 刘亢 一种多弯曲套管中管柱摩擦阻力模拟装置
CN106437519B (zh) * 2016-09-23 2018-07-17 中石化石油工程技术服务有限公司 一种气体钻井近钻扭矩测量方法
WO2019232006A1 (fr) * 2018-05-30 2019-12-05 Knjb, Inc. Mécanisme et procédé de roue à rochet de fond de trou
US11624666B2 (en) 2018-06-01 2023-04-11 Schlumberger Technology Corporation Estimating downhole RPM oscillations
US11916507B2 (en) 2020-03-03 2024-02-27 Schlumberger Technology Corporation Motor angular position control
US11933156B2 (en) 2020-04-28 2024-03-19 Schlumberger Technology Corporation Controller augmenting existing control system
US11655701B2 (en) 2020-05-01 2023-05-23 Baker Hughes Oilfield Operations Llc Autonomous torque and drag monitoring
US11352871B2 (en) 2020-05-11 2022-06-07 Schlumberger Technology Corporation Slide drilling overshot control
US11814943B2 (en) 2020-12-04 2023-11-14 Schlumberger Technoloyg Corporation Slide drilling control based on top drive torque and rotational distance

Family Cites Families (12)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US6050348A (en) 1997-06-17 2000-04-18 Canrig Drilling Technology Ltd. Drilling method and apparatus
US6837315B2 (en) 2001-05-09 2005-01-04 Schlumberger Technology Corporation Rotary steerable drilling tool
DE10149018B4 (de) * 2001-10-04 2007-05-24 Tracto-Technik Gmbh Verfahren zum Richtungsbohren
US7044238B2 (en) 2002-04-19 2006-05-16 Hutchinson Mark W Method for improving drilling depth measurements
US6802378B2 (en) * 2002-12-19 2004-10-12 Noble Engineering And Development, Ltd. Method of and apparatus for directional drilling
US6918453B2 (en) 2002-12-19 2005-07-19 Noble Engineering And Development Ltd. Method of and apparatus for directional drilling
US7096979B2 (en) * 2003-05-10 2006-08-29 Noble Drilling Services Inc. Continuous on-bottom directional drilling method and system
WO2006044737A2 (fr) 2004-10-20 2006-04-27 Comprehensive Power Inc. Procede et systeme de commande de forage directionnel
US7461705B2 (en) * 2006-05-05 2008-12-09 Varco I/P, Inc. Directional drilling control
US7810584B2 (en) 2006-09-20 2010-10-12 Smith International, Inc. Method of directional drilling with steerable drilling motor
US8534354B2 (en) 2010-03-05 2013-09-17 Schlumberger Technology Corporation Completion string deployment in a subterranean well
RU2572093C2 (ru) 2010-12-13 2015-12-27 Шлюмбергер Текнолоджи Б.В. Оптимизированное бурение

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
None *

Also Published As

Publication number Publication date
CA2877925C (fr) 2020-09-29
AU2013286986B2 (en) 2015-12-03
EP2870320A1 (fr) 2015-05-13
WO2014008115A1 (fr) 2014-01-09
CA2877925A1 (fr) 2014-01-09
US20140008126A1 (en) 2014-01-09
US9145768B2 (en) 2015-09-29
AU2013286986A1 (en) 2015-01-22
EP2870320A4 (fr) 2016-03-23
MX2014015995A (es) 2015-03-20
MX364163B (es) 2019-04-15

Similar Documents

Publication Publication Date Title
EP2870320B1 (fr) Procédé de réduction du broutement en cours de forage de puits
AU2013363641B2 (en) Automated directional drilling system and method using steerable motors
AU2004239298B2 (en) Method of and system for directional drilling
US7044239B2 (en) System and method for automatic drilling to maintain equivalent circulating density at a preferred value
CA2663533C (fr) Procede de forage directionnel avec moteur de forage orientable
EP2118441B1 (fr) Composants de forage et systèmes pour contrôler de manière dynamique des dysfonctionnements en termes de forage et procédés de forage d'un puits avec ceux-ci
CA2978296C (fr) Attenuation de glissement saccade sur les systemes d'entrainement superieur a entrainement direct
US10094209B2 (en) Drill pipe oscillation regime for slide drilling
CA2509347C (fr) Procede et appareil pour le forage dirige
AU2015270910B2 (en) Method and system for directional drilling
US10851640B2 (en) Nonstop transition from rotary drilling to slide drilling
WO2009065107A1 (fr) Procédé et système permettant de réguler la force lors d'une opération de forage

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

17P Request for examination filed

Effective date: 20150114

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

AX Request for extension of the european patent

Extension state: BA ME

DAX Request for extension of the european patent (deleted)
RA4 Supplementary search report drawn up and despatched (corrected)

Effective date: 20160218

RIC1 Information provided on ipc code assigned before grant

Ipc: E21B 47/007 20120101AFI20160212BHEP

Ipc: E21B 47/01 20120101ALI20160212BHEP

Ipc: E21B 44/00 20060101ALI20160212BHEP

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: EXAMINATION IS IN PROGRESS

17Q First examination report despatched

Effective date: 20170526

REG Reference to a national code

Ref country code: DE

Ref legal event code: R079

Ref document number: 602013062914

Country of ref document: DE

Free format text: PREVIOUS MAIN CLASS: E21B0047007000

Ipc: E21B0007060000

GRAP Despatch of communication of intention to grant a patent

Free format text: ORIGINAL CODE: EPIDOSNIGR1

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: GRANT OF PATENT IS INTENDED

RIC1 Information provided on ipc code assigned before grant

Ipc: E21B 7/06 20060101AFI20190524BHEP

INTG Intention to grant announced

Effective date: 20190617

GRAS Grant fee paid

Free format text: ORIGINAL CODE: EPIDOSNIGR3

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE PATENT HAS BEEN GRANTED

AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AL AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO RS SE SI SK SM TR

REG Reference to a national code

Ref country code: CH

Ref legal event code: EP

Ref country code: AT

Ref legal event code: REF

Ref document number: 1201816

Country of ref document: AT

Kind code of ref document: T

Effective date: 20191115

REG Reference to a national code

Ref country code: DE

Ref legal event code: R096

Ref document number: 602013062914

Country of ref document: DE

REG Reference to a national code

Ref country code: IE

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: NL

Ref legal event code: MP

Effective date: 20191113

REG Reference to a national code

Ref country code: LT

Ref legal event code: MG4D

REG Reference to a national code

Ref country code: NO

Ref legal event code: T2

Effective date: 20191113

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: NL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: LV

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: SE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: BG

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20200213

Ref country code: FI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: LT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: PL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: PT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20200313

Ref country code: ES

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: GR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20200214

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: HR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: RS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20200313

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: AL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: RO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: CZ

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: DK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: EE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

REG Reference to a national code

Ref country code: DE

Ref legal event code: R097

Ref document number: 602013062914

Country of ref document: DE

REG Reference to a national code

Ref country code: AT

Ref legal event code: MK05

Ref document number: 1201816

Country of ref document: AT

Kind code of ref document: T

Effective date: 20191113

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: SK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: SM

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

26N No opposition filed

Effective date: 20200814

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: SI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: AT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

REG Reference to a national code

Ref country code: DE

Ref legal event code: R119

Ref document number: 602013062914

Country of ref document: DE

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: MC

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

REG Reference to a national code

Ref country code: CH

Ref legal event code: PL

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LU

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20200628

REG Reference to a national code

Ref country code: BE

Ref legal event code: MM

Effective date: 20200630

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CH

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20200630

Ref country code: IE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20200628

Ref country code: LI

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20200630

Ref country code: FR

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20200630

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: DE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20210101

Ref country code: BE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20200630

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: TR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: MT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

Ref country code: CY

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191113

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: NO

Payment date: 20230608

Year of fee payment: 11

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GB

Payment date: 20230504

Year of fee payment: 11

P01 Opt-out of the competence of the unified patent court (upc) registered

Effective date: 20231208